Treatment of subterranean formations

ABSTRACT

A method, wellbore, and pill for treating a region of a subterranean formation adjacent a wellbore zone of the wellbore, including injecting a gellable treatment composition (e.g., as the pill) through the wellbore zone into the region of the subterranean formation adjacent the wellbore zone, allowing the gellable treatment composition to form nanoparticles in-situ in the region and gel in the region via heat provided by the region to prevent or reduce flow of an unwanted fluid from the region into the wellbore zone. The gellable treatment composition may include a zwitterionic gemini surfactant (ZGS).

TECHNICAL FIELD

This disclosure relates to shutoff of unwanted fluids produced from asubterranean formation into a wellbore.

BACKGROUND

A wellbore in a subterranean formation in the Earth crust may betreated. The treatments of the wellbore may treat the subterraneanformation. The wellbore treatments may facilitate production ofhydrocarbon, such as crude oil, from the subterranean formation. Aproblematic section of a wellbore to be treated may be a water zone inwhich water enters the wellbore from the hydrocarbon formation orunderlying water aquifer. The influx of water into the wellbore duringproduction of crude oil can add cost. The production of water along withthe crude oil from the hydrocarbon formation can lead to surfaceprocessing of the water and injection of the water back into thehydrocarbon formation for disposal or pressure maintenance. Suchprocessing and injection of water produced from the wellbore water zonecauses increased costs of the oil production.

In certain instances, natural gas may also be an unwanted producedfluid. Thus, a gas zone in the wellbore may be a problematic section ofthe wellbore (and associated region of the subterranean formation) to betreated. Natural gas as a produced unwanted gas is generally separatedand flared before the crude oil is distributed. In some operations,gas-handling capabilities are not readily available at the well site.

SUMMARY

An aspect relates to a method of treating a region of a subterraneanformation adjacent a wellbore zone of a wellbore, the method includinginjecting a gellable treatment composition through the wellbore zoneinto the region of the subterranean formation adjacent the wellborezone, allowing the gellable treatment composition to gel in the regionvia heat provided by the region to prevent or reduce flow of an unwantedfluid from the region into the wellbore zone, wherein allowing thegellable treatment composition to gel includes forming nanoparticlesin-situ in the region via the gellable treatment composition. Thegellable treatment composition may include a zwitterionic geminisurfactant. The method includes producing desired hydrocarbon from thesubterranean formation through the wellbore to Earth surface, wherein agel formed from the gellable treatment composition in the regionprevents or reduces production of the unwanted fluid from the regioninto the wellbore, and wherein the gel includes the nanoparticles.

Another aspect is a wellbore in a subterranean formation, the wellboreincluding a wellbore zone having a gel that restricts flow of fluid fromthe subterranean formation into the wellbore at the wellbore zone,wherein the gel includes zwitterionic gemini surfactant and silicananoparticles.

Yet another aspect is a pill that is a pill as applied to a wellboreformed through Earth surface in a subterranean formation, the pillincluding a zwitterionic gemini surfactant (ZGS), a salt, anorthosilicate, an acid, and water.

The details of one or more implementations are set forth in theaccompanying drawings and the description below. Other features andadvantages will be apparent from the description and drawings, and fromthe claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of example structures of zwitterionic geminisurfactants.

FIGS. 2-5 are diagrams of a well site having a wellbore formed throughthe Earth surface into a subterranean formation in the Earth crust.

FIG. 6 is a block flow diagram of a method of treating a region of asubterranean formation adjacent a wellbore zone of a wellbore

FIG. 7 is an image of an inverted vial from the Example.

DETAILED DESCRIPTION

Some aspects of the present disclosure are directed to applying ashutoff material into a wellbore for water shutoff or gas shutoff, orboth. The shutoff material may have the following components: (1) aviscoelastic surfactant (VES) that is a zwitterionic gemini surfactant,such as the structures depicted in FIG. 1 ; (2) an activator (e.g.,salt, such as calcium chloride or other salts) to gel the VES; (3) anorthosilicate; and (4) a catalytic amount of acid (e.g., hydrochloricacid) to convert the orthosilicate in-situ (downhole) to silicananoparticles. The orthosilicate may be, for example, tetraethylorthosilicate (TEOS) [Si(OC₂H₅)₄] or tetramethyl orthosilicate (TMOS)[Si(OCH₃)₄], or a combination thereof. Alternatives to orthosilicate assources of silica (silicon dioxide) for forming silica nanoparticlesin-situ may include, for example, silicic acid and sodium silicate.

The composition (shutoff material) exhibits gelation as the temperatureincreases. In application, the shutoff material may be pumped (e.g., asa pill) from the surface into the wellbore to the water zone or gaszone. While the shutoff material may have a modest viscosity at theEarth surface, the material advantageously exhibits shear thinningbehavior in the pumping of the material downhole—thus, the viscosity islowered benefitting the pumping. At the water zone or gas zone, the VES,activator, and in-situ formed nanoparticles give a viscous gel atformation temperature. The orthosilicate (along with the acid) gives thesilica (SiO₂) nanoparticles generated in-situ in the wellbore atformation temperature. The viscous gel having or formed from the silicananoparticles plugs permeability at the zone for shutoff. The zone maybe a water zone and the shutoff may be water shutoff. The zone may be agas zone and the shutoff may be gas shutoff. The shut off material mayplug formation permeability. The shut off material may gel in theformation, forming a solid barrier to flow.

Some aspects of the present disclosure are directed to utilizing azwitterionic gemini surfactant in the treatment of a zone of a wellboreincluding the near wellbore region. Beneficial aspects of thezwitterionic gemini surfactant compared to other viscoelasticsurfactants may be that structural characteristics of zwitterionicgemini surfactants include a relatively large number of hydrophilicgroups, which enable zwitterionic gemini surfactants to self-assemblefor their enhanced viscosification. Moreover, the zwitterionic geminisurfactants may also enjoy advantages of decreasing absorption loss,less damage of the reservoir, and improved adaptability of active agentsto high salinity. See Kamal, M. S. (2016) A review of Geminisurfactants: Potential application in enhanced oil recovery, Journal ofSurfactants and Detergents, 19:223-236,https://doi.org/10.1007/s11743-015-1776-5.

A surfactant may be a substance that reduces surface tension of a liquidin which the surfactant is dissolved. Surfactants may be compounds thatlower the surface tension (or interfacial tension) between two liquids,between a gas and a liquid, or between a liquid and a solid. Surfactantscan be generally amphiphilic compounds, meaning they contain two or moregroups that in pure form are insoluble in each other. A geminisurfactant may include two surfactant molecules chemically bondedtogether by a spacer. Gemini surfactants, sometimes called dimericsurfactants, may have two hydrophilic head groups and two hydrophobicgroups in the molecule. Gemini surfactants may be composed of twohydrophilic head groups and two hydrophobic tails linked by a spacer. Azwitterion may be a molecule that has at least two functional groups:one having a positive charge and the other having a negative charge,with an overall charge of zero. A zwitterion may be a molecule thatcontains an equal number of positively- and negatively-chargedfunctional groups. Zwitterionic surfactants may be amphiphilic organiccompounds that hold hydrophobic groups in their molecular tail andhydrophilic groups in their molecular head. The zwitterionic geminisurfactant may be viscoelastic surfactant (VES). VES fluids are commonlyutilized in hydraulic fracturing. Under certain conditions, VESmolecules arrange into colloidal structures called micelles. With thesestructures in some instances, the hydrocarbon tails of the surfactantsorient toward each other while the polar head groups form an interfacewith the surrounding aqueous media. As appreciated by one of ordinaryskill in the art, the surfactant as a VES may be capable of forming awormlike micelle that can entangle and thus impart viscosity to thefluid. The fluid system may include salt to drive formation of themicelles, such as worm-like micelles that entangle.

Embodiments include a method of sealing a subterranean formationutilizing a zwitterionic gemini surfactant and an activator forapplications such as water shutoff or gas shutoff. This surfactant(solution) in presence of the activator can viscosify to form a solidgel as temperature increases. In implementations, the gellable system(including the surfactant and activator) as a shutoff material can beplaced downhole as a single pill because the gelation process isgenerally temperature activated. Gelling will generally not occur untilthe pill is heated (increased in temperature) by the subterraneanformation. The shutoff material may be a pre-gel shutoff material (apre-gel, gellable system, gellable treatment composition) at the Earthsurface before being pumped into the wellbore. The shutoff material maybe a gel shutoff material (a gel) in the region of the subterraneanformation that is treated with the shutoff material.

The aforementioned in-situ generation of the SiO₂ nanoparticles via thegellable system contributes to the formation of the gel shutoffmaterial. The generating (and thus presence) of the silica nanoparticlesaids with water shutoff (or gas shutoff). The silica nanoparticles areformed in situ during the dissolution of surfactant in a salt solution,such as in a calcium chloride (CaCl₂)) solution. The produced silicananoparticles are transformed as the fluid heats up into polymeric gelthat blocks the water channels by reducing the permeability of thewater-producing zone. Such generally aides in blocking unwanted waterproduction into the wellbore. The diameter of the SiO₂ nanoparticles maybe, for example, less than 150 nanometers (nm). In the subterraneanformation at the wellbore zone of interest, the acid, e.g., hydrochloricacid (HCl), catalyzes the reaction of the orthosilicate (e.g., TEOS,TMOS, etc.) into the SiO₂ nanoparticles. The reaction may involve thehydrolysis of monomeric orthosilicate and subsequent formation of theSiO₂ nanoparticles. In particular, the acid catalyzes the hydrolysis oforthosilicate (e.g., TEOS) to produce hydrolyzed precursors oforthosilicate (e.g., TEOS). The hydrolyzed precursors are transformed tooligomeric precursors, which leads to the formation of SiO₂nanoparticles. Again, the acid catalyzes the reaction in the gel. Theacid-catalyzed reaction may form or facilitate formation of the gel. Theacid (e.g., HCl) is a catalyst to transform orthosilicate (e.g., TEOS)into silica nanoparticles, which allows for production of polymeric gel.The reaction of orthosilicate (via the acid catalyst) into SiO₂nanoparticles can occur at room temperature. However, the reaction isdelayed at such a low temperature. In contrast, at typicalsubterranean-formation temperature (e.g., at least 50° C., or in therange of 50° C. to 175° C.), the rate of this reaction is increased dueto the higher temperature.

Excessive water production can reduce the economic life of producingwells. High water cut in produced hydrocarbon can affect the economiclife of producing wells and may contribute to equipment damage, such asby scale deposition, fines migration, asphaltene precipitation,corrosion, etc. Moreover, the processing to separate, treat, and disposeof the produced water leads to increased operating costs. Embodiments ofthe present techniques provide for shutoff of water in water-producingzones. Embodiments may also provide for shutoff of natural gas innatural-gas producing zones, such as when natural gas is an unwanted(undesired) produced fluid. The shutoff material as a conformancematerial is generally based on an activation chemistry to gel thezwitterionic viscoelastic surfactant. The in-situ formation of thesilica nanoparticles contributes to the shutoff.

Implementations include employing a shutoff material composition indownhole conditions for water shutoff (or gas shutoff). The shutoffmaterial as formulated prior to application may be labeled as a gellabletreatment composition. As indicated, the shutoff material composition asformulated at the Earth surface (e.g., adjacent the wellbore) mayinclude: zwitterionic gemini surfactant (a viscoelastic surfactant),activator (e.g., salt), orthosilicate (e.g., TEOS), and acid as catalystfor the orthosilicate. The combination of zwitterionic dispersion withactivator may result in a gelled solid-based shutoff material for watershutoff (or gas shutoff). Salt (e.g., calcium chloride) may act as anactivator that gels the zwitterionic gemini surfactant. As indicated, inembodiments of methods to prevent unwanted water (or gas) production,the zwitterionic gemini surfactant and the activator (along with theorthosilicate and the acid) may be pumped (or otherwise applied)downhole as a single pill. The shutoff composition may generally gel asthe temperature increases under downhole conditions.

FIG. 1 is an example of structures of zwitterionic gemini surfactantsthat may be employed in the shutoff material of the present techniques.The zwitterionic gemini surfactants may be labeled as short-chainzwitterionic gemini surfactant in that the number of carbons in themolecule is generally less than 30. The value of n can be, for example,n₁=8-18, n₂=3-6, and n₃=3-4. The R functional group (at each end) canbe, for example, sulfonates, carboxylates, aldehydes, alcohols, etc.Thus, R can be, for example, a sulfonate, a carboxylate, an aldehyde, oran alcohol. The zwitterionic gemini surfactant employed can be aspecific structure of the structures represented by FIG. 1 , or amixture of the depicted structures having differing values for n and/ordifferent end functional groups, and the like.

The shutoff material initially as a gellable treatment composition asformulated at the Earth surface may have the following components: (1) azwitterionic gemini surfactant (a VES); (2) an activator (e.g., salt) togel the VES; (3) orthosilicate (e.g., TEOS); and (4) a catalytic amountof acid (e.g., HCl) to convert the orthosilicate in-situ (downhole) tosilica nanoparticles. The gellable composition as prepared at surface isan aqueous composition. Examples of the zwitterionic gemini surfactant(ZGS) include the structures depicted in FIG. 1 . Other zwitterionicgemini surfactants are applicable. The activator as an inorganic salt oran organic salt, or a combination thereof. The inorganic salt may be,for example, calcium chloride, sodium chloride, potassium chloride, orsodium bromide, or any combinations thereof. The organic salt may be,for example, sodium citrate or sodium salicylate, or a combinationthereof. Other salts for viscosity buildup are applicable. Examplenumerical ranges in weight percent (wt %) for the gellable composition(e.g., as a pill) are ZGS (2.5 wt % to 10 wt %), salt (5 wt % to 30 wt%), orthosilicate (1 wt % to 10 wt %), acid (at least one molarequivalent to the orthosilicate) and the balance is water for theformulation at 100 wt %. The amount of water may be, for instance, inthe range of 60 wt % to 85 wt %. These numerical ranges are given asexamples. Moreover, additional compounds or components may be includedin the gellable treatment composition (shutoff material as formulated atsurface). In some implementations of these given examples of numericalranges of component concentrations, the acid is HCl, the salt is calciumchloride, and the orthosilicate is TEOS.

Lastly, as discussed, the R functional group (at each end) in FIG. 1 canbe, for example, a sulfonate group (SO₃ ⁻), a carboxylate group (CO₂ ⁻),an aldehyde functional group (—CHO), or a hydroxyl functional group(—OH). A carboxyl group (COOH) is a functional group consisting of acarbonyl group (C═O) with a hydroxyl group (OH) attached to the samecarbon atom.

An aldehyde group is a functional group with the structure —CHO,consisting of a carbonyl center (a carbon double-bonded to oxygen) withthe carbon atom also bonded to hydrogen. This functional group itself isknown as an aldehyde or formyl group.

FIG. 2 is a well site 100 having a wellbore 102 formed through the Earthsurface 104 into a subterranean formation 106 in the Earth crust. Asdescribed below, the gellable shutoff material described above, e.g.,composition including ZGS, activator (e.g., salt), orthosilicate (e.g.,TEOS), acid (e.g., HCl), and water) may be the gellable treatmentcomposition 120 to be applied through the wellbore 102 to treat theformation 106. The subterranean formation 106 may also be labeled as ageological formation, hydrocarbon formation, hydrocarbon reservoir, etc.Hydrocarbon is produced from the subterranean formation 106 through thewellbore 102 to the surface 104. The hydrocarbon may be crude oil ornatural gas, or both. To produce the hydrocarbon, the hydrocarbon mayflow from the subterranean formation 106 into the wellbore 102, and theninto tubing 108 (e.g., production tubing) to flow to the surface 104.The “tubing” 108 as used herein is a generic term to include a conduit,tubing having perforations or holes, pre-perforated liner (PPL),production screens, and the like. In the illustrated embodiment, thehydrocarbon may flow from the formation 106 into the tubing 108 throughentry components 110 disposed along the tubing 108. The entry components110 may be, for example, holes, perforations, slots, mesh, valves, etc.The tubing 108 may be perforated tubing or perforated liner having theentry components 110 as perforations (holes) or slots. The tubing 108may be a conduit, production conduit, production tubing, tubing withperforations, holes, or slots, PPL, production screens, etc. An annulus111 in the wellbore 102 may be defined by the tubing 110 and theformation surface 112 or wellbore wall. The entry components 110 mayallow for flow of fluid from the annulus 111 into the tubing 106. Theentry components 110 may allow for flow of fluid (e.g., treatment fluidor treatment slurry) from the production tubing 110 into the annulus 111and thus into the formation 106.

To form the wellbore 102, a hole is drilled into the subterraneanformation 106 to generate the formation surface 112 (formation face) asan interface for the wellbore 102 with the subterranean formation 106.The formation surface 112 (wellbore wall) can be characterized as a wallof the wellbore 102. For a cased wellbore (not shown), the casing can becharacterized as the wellbore 102 wall. The wellbore 102 diameter maybe, for example, in a range from about 3.5 inches (8.9 centimeters) to30 inches (76 centimeters), or outside of this range. The depth of thewellbore 102 can range from 300 feet (100 meters) to more than 30,000feet (9,100 meters). The wellbore 102 can be vertical, horizontal, ordeviated, or any combinations thereof. Once the wellbore 102 is drilled,the wellbore 102 may be completed.

The wellbore 102 may be openhole (as depicted) or have a cemented casing(not shown). For implementations with the wellbore 102 as cased, theremay be cement between the casing and the formation surface 112.Perforations may be formed through the casing and cement into thesubterranean formation 106 to facilitate or provide for hydrocarbonproduction from the subterranean formation 106 into the wellbore 102. Inimplementations, the perforations through the casing and cement may alsoaccommodate the injection of fluids (e.g., including treatmentcompositions) from the wellbore 102 into the subterranean formation 106.

The wellbore 102 may be completed with multiple completion packers 114disposed along the depth of the wellbore 102. The packers 114 maysupport the tubing 108 (e.g., support the weight of the tubing 108) andgenerally prevent or reduce movement of the tubing 108. The packers 114may mechanically isolate sections of the annulus 111 between the tubing108 and the formation surface 112. The packers 114 may be downholedevices installed in wellbore completions for isolation to facilitatecontrol of production, injection, or treatment. The packers 114 (inisolating sections of the annulus 111) may separate the wellbore 102into multiple zones (e.g., producing zones).

In the illustrated embodiment, the particular zone 116 (e.g., aproducing zone) is a problematic zone in that a significant amount ofunwanted fluid 118 enters the wellbore 102 from the subterraneanformation 106. The zone 116 may be defined by the adjacent uppercompletion packer 114 and the adjacent lower completion packer 114. Inimplementations, the unwanted fluid 118 may be the majority of the totalfluid that enters the wellbore 102 from the subterranean formation 106at the zone 116. The total fluid that enters the wellbore 102 may be acombination of desired fluid (e.g., crude oil) and the unwanted fluid118.

In some implementations, the unwanted fluid 118 is water and thus thezone 116 may be labeled as a water zone. Excessive water production fromhydrocarbon-producing wells can adversely affect the economic life ofthe well. Unwanted water production can unfavorably influence welleconomics owing to handling of the produced water, reduction ofhydrocarbon production, and environmental concerns.

In certain implementations, the fluid 118 may be natural gas that isunwanted because the well site 100 prefers production of crude oil andmay not have surface facilities to collect and distribute the naturalgas as product. Natural gas as a produced unwanted gas is generallyseparated and flared before the crude oil is distributed.

In embodiments, a gellable treatment composition 120 that is thermallyactivated downhole in the formation into a gel is applied to plug thesubterranean formation 106 at the wellbore zone 116 to reduce or preventthe flow of the unwanted fluid 118 into the wellbore 102. The gellabletreatment composition 120 is above-described present shutoff material.This treatment may isolate the formation 106 at the wellbore zone 116from the wellbore 102. The treatment can be characterized as selectivezonal isolation. This treatment of the formation 106 at the wellborezone 116 may be characterized as shutoff of the unwanted fluid 118. Forinstances of the unwanted fluid 118 as water, the shutoff via thetreatment may be labeled as water shutoff. For instances of the unwantedfluid 118 as gas (e.g., natural gas), the shutoff via the treatment maybe labeled as gas shutoff.

The gellable treatment composition 120 as the aforementioned presentshutoff-material composition as pumped from the surface 104 into thewellbore 102 may be labeled as a pre-gel or a precursor composition fora gel. The activator (salt) may promote (along with increasingtemperature) the forming of the gel from the gellable treatmentcomposition 120. The activator may increase the rate of formation of thegel. In other words, the presence of the activator may decrease theamount of time for the treatment composition 120 to gel at a givengelling temperature.

Embodiments may treat the wellbore zone 116 to plug porosity orfractures in the region of the subterranean formation 106 adjacent thezone 116 to prevent or reduce the flow of unwanted fluid 118 into thewellbore 102. The treatment may involve injection of the gellabletreatment composition 120 (above-described gellable shutoff composition)into the wellbore 102 to the zone 116 of interest (and into theformation 106 at the zone 116).

The gellable composition 120 is thermally activated via formation 106temperature into a gel (e.g., polymer gel or resin). The formationtemperature 106 along with the acid (e.g., HCl) promotes conversion ofthe orthosilicate (e.g., TEOS) to silica nanoparticles in the gel. Atthe wellbore zone 116, the gel may damage (e.g., plug the porosity of)the formation face 112 and the near wellbore region of the subterraneanformation 106. Such may reduce or prevent the flow of the unwanted fluid118 into the zone 106, which stops or reduces the influx of the unwantedfluid 118 into the wellbore 102. The gel as gelled (cured) may solidify.The gellable treatment composition 120 may be activated via theactivator (salt) in the composition 120 into a gel at a temperature(e.g., formation 106 temperature) greater than surface 104 ambienttemperature. The composition 102 may gel at formation 106 temperatureand with the activator salt acting as an accelerator of the gelling.

The gellable treatment composition 120 may be held as a pre-gel in avessel of surface equipment 122 at the surface 104 and then introduced(e.g., via a pump 124 of the surface equipment 122) into the wellbore102. The composition 120 may be formulated as a pill. The gellabletreatment composition 120 may be introduced (e.g., pumped) into thewellbore 102. The gellable treatment composition 120 may be pumped by asurface pump 124 of the surface equipment 122 at the surface 104. Thepump(s) 124 can be skid-mounted in some instances. The pump 124 may be acentrifugal pump, positive displacement (PD) pump, reciprocating PD pumpsuch as a piston or plunger pump, and so on. In implementations, thetreatment composition 120 is pumped through coiled tubing into thetubing 108 in the wellbore 102.

The surface equipment 122 at the Earth surface 104 may include equipment(e.g., vessels, piping, pumps, wellhead, etc.) to support operations atthe well site 100 including the production of hydrocarbon (e.g., crudeoil) via the wellbore 102 from the subterranean formation 106. Thesurface equipment 122 may include equipment for drilling, installingcasing, cementing casing, and so forth.

The surface equipment 122 may include equipment to treat the wellbore102, such as the pump(s) 124, downhole devices 126 (to be applied), adeployment extension such as coiled tubing 128 (e.g., to deploy thedownhole devices 126 and flow the treatment composition 120), etc. Thesurface dispenser of the coiled tubing 128 at the surface 104 may be acoiled tubing reel (e.g., mounted on a vehicle).

In the oil and gas industries, coiled tubing generally refers to a metalpipe supplied spooled on a reel. The coiled tubing may be employed forinterventions in oil and gas wells. The coiled tubing may be a flexiblesteel pipe that is inserted into a wellbore to convey well servicingtools and to flow fluids or slurries. In implementations, the coiledtubing may be constructed of strips of steel rolled and seam welded. Thetubing may be flexible to be coiled onto a reel, and with diameters inthe range, for example, of ¾ inch to 3½ inch, or 1 inch to 3¼ inch.

The downhole devices 126 may be lowered into the wellbore 102 via adeployment extension (e.g., wireline, slickline, coiled tubing 128,etc.). The deployment extension from the Earth surface 104 at thewellbore 102 may lower or deploy a downhole device 126 into the wellbore102. Thus, some downhole devices 126 may be deployed or lowered into thewellbore 102 via a wireline or coil tubing 128. In implementations,deployment and retrieval of the downhole devices 126 may be a riglessoperation such as via wireline, slickline, coiled tubing, and the like.A rigless operation may be a well intervention conducted with equipmentand support facilities that preclude the requirement for a rig over thewellbore.

The surface equipment 122 may include the downhole devices 126 to bedeployed into the wellbore 102 for treatment of the wellbore 102including facilitating application of the gellable treatment composition120 to the zone 116 of interest. In implementations, the downholedevices 126 may be deployed via the coiled tubing 128 or other similardeployment extension. Thus, the application of the gellable treatmentcomposition 120 to the wellbore 102 may be a rigless operation.

The use of [1] the coiled tubing 128 (into tubing 108), [2] deploymentof the downhole devices 126 (into tubing 108) via the coiled tubing 128,and [3] introduction of the gellable treatment composition 120 throughthe coiled tubing 128 in the tubing 108 are indicated by referencenumeral 130.

The devices 126 may include, for example, a retrievable bridge plug tobe deployed (e.g., via coiled tubing 128) inside the tubing 108 to thelower completion packer 114 at the zone 116. The retrievable bridge plugmay isolate the tubing 108 from further downhole in preventing downholeflow through the tubing 108 pass the depth of the lower completionpacker 114 at the zone 116. The devices 126 may include, for example, aretrievable production packer to be deployed (e.g., via coiled tubing128) inside the tubing 108 to the upper completion packer 114 at thezone 106. The retrievable production packer may direct the gellabletreatment composition 120 (pumped from the surface 104 through thecoiled tubing 126) into the zone 106. The treatment composition 120 maydischarge from the coiled tubing in the tubing 108 at the zone 116 andflow through entry components 110 into the annulus 111 in zone 116.

At the zone 106 (annulus 111 isolated via packers 114), the gellabletreatment composition 120 may flow from the annulus 111 into thesubterranean formation 106. The motive force for flow of the treatmentcomposition 120 may be provided by the surface pump 124. The treatmentcomposition 120 as applied may gel in the formation 106, such as in thenear wellbore region at the depth of the zone 106. The gel may foul(plug porosity) of the subterranean formation 106 in this near wellboreregion at the zone 116 depth to stop or reduce the flow of the unwantedfluid 118 into the wellbore 102. The plugging of the formation face 112and near wellbore region of the subterranean formation 106 at thewellbore zone 116 with the gel may isolate the zone 116 from thewellbore 102 and from contributing to production through the tubing 108to the surface 104.

After completion of pumping the gellable treatment composition 120 intothe wellbore 102, the downhole devices 126 (e.g., retrievable bridgeplug and retrievable production packer) may be available for removal.

As discussed, the wellbore 102 may be openhole without casing or liner.For embodiments with the wellbore 102 as a cemented cased wellbore withor without the presence of completion packers 114, a downhole device 126deployed to apply the gellable treatment composition 120 may be, forexample, a straddle packer. The straddle packer may be deployed (e.g.,via coiled tubing 128) to mechanically isolate a wellbore zone ofinterest (e.g., water zone, gas zone, etc.). In these implementations,the gellable treatment composition 120 may be pumped via pump 124through coiled tubing 128 to the straddle packer and ejected from anipple on the straddle packer into the zone. The zone may bemechanically isolated by the straddle packer the upper and lowerinflatable elements of the straddle packer. The gellable treatmentcomposition 120 as ejected by the straddle packer nipple may flowthrough the perforations through the cemented casing into thesubterranean formation 106. The motive force for flow of the composition120 through the perforations into the subterranean formation 106 may beprovided by the pump 124. Again, the composition 120 is the gellableshutoff material (e.g., composition including ZGS, salt, TEOS, HCl,water) described above.

FIG. 3 is a well site 1100 having a wellbore 1102 through the Earthsurface 1104 into a subterranean formation 1106 in the Earth crust. Thesubterranean formation 1106 may also be labeled as a geologicalformation, hydrocarbon formation, hydrocarbon reservoir, etc.Hydrocarbon is produced from the subterranean formation 1106 through thewellbore 1102 to the surface 1104. The hydrocarbon may be crude oil ornatural gas, or both. To form the wellbore 1102, a hole is drilled intothe subterranean formation 1106 to generate a formation surface 1108 asan interface for the wellbore 1102 with the subterranean formation 1106.The formation surface 1108 can be characterized as a wall of thewellbore 1102. The wellbore 1102 may be openhole or have a casing (notshown).

The illustrated wellbore 1102 has a water zone to be isolated. A waterzone is an example of a problematic section in a wellbore 1102. Thewellbore 1102 wall in the water zone may be the subterranean formation1106 interface (formation surface 1108) defining that portion of thewellbore. Water 1110 may enter at a water zone into the productionfluid. The water zone may include a permeable or fractured interface ofthe formation surface 1108 of the wellbore 1102. This problematic zonecan be a water-producing zone within a hydrocarbon-producing zone. Atthe water zone, water 1110 enters the wellbore 1102 from thesubterranean formation 1106. The water zone may be isolated to restrictintroduction of the water 1110 into the wellbore 1102. The water zonemay be isolated to prevent receipt of the water 1110 into the fluidflowing through the wellbore 1102. For example, the isolation mayinhibit flow of the water 1110 into the produced hydrocarbon flowingthrough the wellbore 1102 to the Earth surface 1104. The isolation ofthe water zone involves treatment of the region of the formation 1106 atthe water zone with the gellable treatment composition 1116 (analogousto gellable treatment composition 120 of FIG. 2 ) that is the gellableshutoff material described above, e.g., composition including ZGS,activator (salt), orthosilicate, acid, and water. The treatment maydamage the formation 1106 to plug or reduce porosity by plugging thepores at the formation surface 1108 in the water zone. The orthosilicate(e.g., TEOS) is converted via the acid into silica nanoparticles in situin the formation 1106. The ZGS may gel via the activator (e.g., salt)and the silica nanoparticles. The gel with the silica nanoparticles maysolidify.

In the illustrated embodiment, an application device 1112 applies thegellable treatment composition 1116 to the water zone. Application ofthe gellable treatment composition 1116 plugs the formation 1106 at thewater zone to isolate the water zone. The application device 1112 mayinclude a chamber 1114 (inner cavity) containing the gellable treatmentcomposition 1116 to be applied. The application device 1112 may have anozzle or nipple 1118 to inject the gellable treatment composition 1116from the chamber 1114. Again, the gellable treatment composition 1116 isthe gellable shutoff material composition discussed herein, e.g.,including ZGS, activator (salt), TEOS, acid (HCl), and water. In oneimplementation, the application device 1112 has a piston to push thegellable treatment composition 1116 from the chamber 1114 through thenozzle or nipple 1118. The application device 1112 may have multiplenozzles or nipples 1118. In some implementations, the application device1112 is a straddle packer having the chamber 1114 and the nipple 1118.The gellable treatment composition 1116 injected from the applicationdevice 1112 (discharged or ejected through the nipple 1118) may contactthe formation surface 1108 at the water zone to plug or foul theformation 1106 at the water zone.

To deploy the application device 1112, a deployment extension 1120 froma dispenser 1122 may lower the application device 1112 into the wellbore1102. For application devices 1112 that are temporary or retrievable,the deployment extension 1120 may retrieve (raise, pull, remove) theapplication device 1112 from the wellbore 1102. In some implementations,the deployment extension 1120 is coiled tubing and the dispenser 1122 isa coiled tubing reel. In other implementations, the deployment extension1120 is a wireline and the dispenser 1122 is a wireline truck. Thedeployment extension 1120 may be a conduit, cable, slickline, workstring, drill string, or jointed pipe. The application device 1112 maybe lowered to the water zone and then activated. When activated, theapplication device 1112 anchors (e.g., via mechanical slips) anddischarges (ejects) the gellable treatment composition 1116 from thechamber through application-packer nozzle(s) 1118.

The application device 1112 may be a straddle packer or modifiedstraddle packer. A straddle packer may be modified to incorporatefeatures (for example, the gellable treatment composition chamber 1114and nozzles 1118) of the application device 1112 if needed orapplicable. Straddle packers (whether hydraulic or electric) may providefor isolation of a wellbore zone. Straddle packers and bridge plugs mayprovide zonal isolation in a wellbore. Present embodiments include astraddle packer having a chamber or inner cavity that carries thegellable treatment composition. When the straddle packer is activated,the straddle packer may anchor (mechanically set) against the formationsurface 1108 and eject the gellable treatment composition to facilitateisolation of the zone of interest. Again, the application device 1112may be a straddle packer having a chamber 1114 to carry the gellabletreatment composition 1116 to isolate the water zone. The straddlepacker having the gellable treatment composition in a chamber may deploy(form) the gellable treatment composition sealing at the water zone.When activated, the straddle packer anchors (mechanically sets) aboveand below the waters, and discharges (ejects) the gellable treatmentcomposition from the chamber through straddle-packer nipple(s) into theregion of the subterranean formation 1106 at the water zone to plug orseal features of the subterranean formation 1106 in the water zone. Thetreatment may be in the near wellbore region of the formation adjacentthe wellbore at the water zone.

Lastly, the unwanted fluid 1110 may be gas or natural gas instead ofwater. The associated wellbore zone (problematic zone) may be a gas zoneinstead of a water zone. The treatment with the gellable treatmentcomposition 1116 (shutoff material) may shutoff flow the gas into thewellbore.

FIG. 4 is a wellbore 1200 formed through the Earth surface 1202 into asubterranean formation 1204. The subterranean formation 1204 includeshydrocarbon reservoir formations 1206 and an intervening water-producingzone 1208. Water may enter the wellbore 1200 from the water-producingzone 1208. That portion of the wellbore 1200 may be labeled as a waterzone. Produced water may refer to subterranean formation water that isco-produced with the crude oil or natural gas. The produced water cancause production problems by generating emulsions, scale, and corrosion.The production of water may incur operational cost because the producedwater must typically be separated from the hydrocarbons.

An inner surface of the wellbore 1200 is the formation surface 1210 ofthe subterranean formation 1204. In the illustrated embodiment, aportion of the wellbore 1200 has a casing 1212 with cement 1214 disposedbetween the casing 1212 and the formation surface 1210. The wellbore1200 has a production tubing 1216 (through a production packer 1218) forthe flow of produced fluid including hydrocarbon to the surface 1202.The hydrocarbon may be crude oil or natural gas that enters the wellbore1200 from the hydrocarbon reservoir formations 1206.

The produced fluid flowing upward through the production tubing 1216also includes water that enters the wellbore 1200 from thewater-producing zone 1208. It may be desired to isolate the water zonein the wellbore 1200 to prevent water from water-producing zone 1208entering the wellbore 1200 and becoming a component of the productionfluid. The isolation of the water zone may be mechanical or chemical (ora combination of mechanical and chemical). The chemical treatment forwater shut-off may be by an application device 1220 that is the same oranalogous to the application device 1110 of FIG. 3 , and in which thegellable treatment composition 1116 is applied (ejected) from theapplication device 1220. In implementations, the application device 1220may be a straddle packer.

The application device 1220 may be deployed via a deployment extension1222 to the water zone in the wellbore (at the water-producing zone1208). In some embodiments, the deployment of the application device1220 into the wellbore 1200 may be rigless. A rigless operation may be awell intervention conducted with equipment and support facilities thatpreclude the requirement for a rig over the wellbore 1200. Thedeployment extension 1222 may be coiled tubing, wireline, or slicklinefor rigless deployment. The application device 1220 or straddle packermay mechanically set at or around the water zone and eject the gellabletreatment composition (e.g., 1116 of FIG. 3 ) into a region of theformation 1204 (at the water-producing zone 1208) to seal the formation1204 at the water zone. The orthosilicate (e.g., TEOS) is converted viathe formation temperature and acid into silica nanoparticles in situ inthe formation 1106. The formation temperature may provide for the ZGS togel via the activator (e.g., salt) and the silica nanoparticles. The gelwith the silica nanoparticles may solidify. Such may restrict or reduceintroduction of water from the water-producing zone 1208 into thewellbore 1200.

Lastly, the water-producing zone 1208 may instead be a natural-gasproducing zone 1208, and in which natural gas is an undesired producedfluid. Thus, the treatment may shutoff introduction of the natural gasinto the wellbore 1200.

FIG. 5 is a well site 1300 having a wellbore 1302 through the Earthsurface 1304 into a subterranean formation 1306 in the Earth crust. Agellable treatment composition 1316 analogous to the gellable treatmentcompositions 120, 1116 (FIGS. 2-3 ) that is the gellable shutoffmaterial described above, e.g., composition including ZGS, activator(salt), TEOS, acid (HCl), and water, may be applied through the wellbore1302 to treat the formation 1306. The subterranean 1306 may also belabeled as a geological formation, hydrocarbon formation, reservoir,etc. Hydrocarbon may be produced from the subterranean formation 1306through the wellbore 1302 to the surface 1304. The hydrocarbon may becrude oil or natural gas, or both. To form the wellbore 1302, a hole(borehole) is drilled into the subterranean formation 1306 to generate adrilled formation surface 1308 as an interface for the wellbore 1302with the subterranean formation 1306. The formation surface 1308 may becharacterized as the wellbore 102 wall. The wellbore 1302 may haveopenhole portions but generally includes a cylindrical casing 1310 asshown. The wellbore 1302 in the depicted implementation of FIG. 5 is acased wellbore 1302. In the illustrated embodiment, the wellbore 1302has a zone 1312 to be treated.

In implementations, the zone 1312 may be a water zone in which water isintroduced into the wellbore 1302 from the subterranean formation 1308.The zone 1312 may be a gas zone in which undesired gas (e.g., naturalgas) is introduced into the wellbore 1302 from the subterraneanformation 1308. The water or gas may be introduced through features 1314(e.g., fractures, permeable channels, high permeability portions, etc.)that contribute to introduction of excess water or excess gas from thesubterranean formation into the wellbore 1302. In some instances, thefeatures 1314 may be typical features along the wellbore 1302 and notresembling the represented emphasized indentations into the formation1308.

The gellable treatment composition 1316 that is the gellable shutoffmaterial discussed herein may be introduced (e.g., pumped) into thewellbore 1302. The gellable treatment composition 1316 as shutoffmaterial flows through the casing 1310, discharges from the bottomportion of the casing 1310, and flows upward through the annulus betweenthe casing 1310 and the formation surface 1308. The gellable treatmentcomposition 1316 may invade the features 1314 to plug or seal thefeatures 1314 in that region of the formation 1306 to stop or reducewater flow (or gas flow) from the subterranean formation 1306 throughthe features 1314 into the wellbore 1302. The treatment may be in nearwellbore region of the formation 1306.

The gellable treatment composition 1316 may be pumped by a surface pump(e.g., mud pump) of the surface equipment 1318 at the surface 1304. Incertain implementations, the pump may be associated with a drilling rig.The pump(s) can be skid-mounted in some instances. The pump may be acentrifugal pump, positive displacement (PD) pump, reciprocating PD pumpsuch as a piston or plunger pump, and so on. The surface equipment 1318may include equipment (e.g., vessels, solid-handling equipment, piping,pumps etc.) for handling or preparing the gellable treatment composition1316. The surface equipment 1318 may include equipment to support otheroperations at the well site 1300.

FIG. 6 is a method 600 of treating a region of a subterranean formationadjacent a wellbore zone of a wellbore. The treatment may be to isolatea wellbore zone with a gellable treatment composition that is shutoffmaterial.

At block 602, the method includes injecting a gellable treatmentcomposition through the wellbore zone into the region of thesubterranean formation adjacent the wellbore zone. The gellabletreatment composition may be a shutoff composition to shutoff the flowof the unwanted fluid into the wellbore zone from the region. Thegellable treatment composition as injected includes ZGS, salt,orthosilicate, acid, and water.

At block 604, the method includes allowing the gellable treatmentcomposition to gel in the region via heat provided by the region toprevent or reduce flow of an unwanted fluid from the region into thewellbore zone, wherein allowing the gellable treatment composition togel includes forming nanoparticles (e.g., silica nanoparticles) in-situin the region via the gellable treatment composition. The unwanted fluidmay include water or natural gas, or both. The gellable treatmentcomposition may include an activator to promote gelling of the gellabletreatment composition in the region along with the heat provided by theregion, wherein the heat provided by the region increases temperaturesof the gellable treatment composition in the region. The gellabletreatment may include ZGS, wherein the activator includes salt, andwherein allowing the gellable treatment composition to gel comprisesgelling of the ZGS in the region via the salt. The gellable treatmentcomposition may include orthosilicate (e.g., TEOS, TMOS, etc.) that iscatalyzed via an acid (e.g., HCl) in the gellable treatment compositioninto the nanoparticles including silica nanoparticles. The gellabletreatment composition may include an activator (e.g., salt) and ZGS thatis a VES, wherein allowing the gellable treatment composition to gelinvolves gelling of the ZGS in the region via the activator, and whereinheat from the region increasing temperature of the gellable treatmentcomposition promotes gelling of the ZGS. The salt may include calciumchloride, sodium chloride, potassium chloride, sodium bromide, sodiumcitrate, or sodium salicylate, or any combinations thereof.

At block 606, the method includes preventing or reducing flow of theunwanted fluid from the region into the wellbore by the presence of theformed get in the region. Such may be characterized as water shutoff forthe unwanted fluid as water, or as gas shutoff for the unwanted fluid asgas (e.g., natural gas).

At block 608, the method includes producing desired hydrocarbon from thesubterranean formation through the wellbore to Earth surface, wherein agel formed from the gellable treatment composition in the regionprevents or reduces production of the unwanted fluid from the region,and wherein the gel includes the nanoparticles (e.g., silicananoparticles). The desired hydrocarbon may be, for example, crude oilor natural gas, or both.

An embodiment is a wellbore in a subterranean formation. The wellboreincludes a wellbore zone having a gel that restricts flow of fluid(e.g., water or natural gas, or both) from the subterranean formationinto the wellbore at the wellbore zone. The gel includes ZGS and silicananoparticles. In implementations, the gel prevents flow of fluid fromthe subterranean formation into the wellbore at the wellbore zone. Inimplementations, the ZGS can be the following structure reproduced fromFIG. 1 , where R can be as given and can be, for example, a sulfonategroup, a carboxylate group, an aldehyde group, or hydroxyl group.

An embodiment is a pill as applied to a wellbore formed through Earthsurface in a subterranean formation. A pill may be quantity of a mixtureto treat a wellbore or associated subterranean formation. The pill asapplied to the wellbore may involve the pill as formulated at the Earthsurface and as injected (e.g., pumped) into the wellbore. The pillincludes ZGS, salt, orthosilicate (e.g., TEOS, TMOS, etc.), acid (e.g.,HCl), and water. The salt may be calcium chloride, sodium chloride,potassium chloride, sodium bromide, sodium citrate, or sodiumsalicylate, or any combinations thereof. In implementations, theconcentration of the ZGS in the pill is in a range of 2.5 wt % to 10 wt%, the concentration of the salt in the pill is in a range of 5 wt % to30 wt %, the concentration of the orthosilicate in the pill is in arange of 1 wt % to 10 wt %, and the concentration of the acid in thepill is at least one molar equivalent to the orthosilicate. Inimplementations, the ZGS (e.g., see FIG. 1 ) can be the structures asdiscussed.

EXAMPLE

The Example is given only as an example and not intended to limit thepresent techniques. The Example reflects in-situ synthesis ofnanoparticles at increasing temperature along with the gelation ofviscoelastic surfactant. For this purpose of nanoparticle synthesis,TEOS was added along with a catalytic amount of dilute HCl to themixture, as discussed below.

Initially, a zwitterionic gemini surfactant (ZGS) was dissolved inCaCl₂) 20 wt % solution in water at ratio of 5 wt %:95 wt % in threedifferent vials separately. The ZGS was the ZGS in FIG. 1 with n₁=8,n₂=3 and n₃=3. Then, TEOS (0.5 mL, 1.5 mL and 3.0 mL, respectively) anda few drops of HCl were added to each vial and the mixture in each vialstirred for 30 minutes at 90° C. The heating and stirring at 90° C. for30 minutes gave a jelly-like product as formed in each of the threevials. The viscosity of the jelly-like product in each vial was measuredat room temperature, 40° C., and 90° C., as portrayed in Table 1. Theviscosity in given in centipoise (cP). The shear rate (for the viscositymeasurement) is given in reciprocal seconds (1/s).

After overnight stay at room temperature, the jelly materialdemonstrated viscosity build-up, as indicated with inversion of thevials. FIG. 7 depicts one of the vials inverted after overnight. FIG. 7indicates the gelation of short-chain ZGS.

It should be noted that the TEOS and HCl solution were sequentiallyadded to the solution mixture of ZGS in CaCl₂). The hydrolysis ofmonomeric TEOS and then formation of SiO₂ nanoparticles was ensuredwithin each same vial. In other words, SiO₂ nanoparticles were producedwithin the same vial in the solution mixture rather than producing theSiO₂ nanoparticles separately and adding the SiO₂ nanoparticles to thesolution. The HCl catalyzes the hydrolysis of TEOS to produce tohydrolyzed precursors of TEOS. The hydrolyzed precursors are thentransformed to oligomeric precursors, which eventually lead to theformation of SiO₂ nanoparticles.

TABLE 1 Viscosification results of ZGS with SiO₂ in CaCl₂ solutions(20%) ZGS-5% + CaCl₂(20%)-95% + ZGS-5% + CaCl₂(20%)-95% + ZGS-5% +CaCl₂(20%)-95% + Shear TEOS(0.5 mL) TEOS(1.5 mL) TEOS(3.0 mL) Rate RT40° C. 90° C. RT 40° C. 90° C. RT 40° C. 90° C. 1.02 343.8 351.6 1258343.8 351.6 382.8 335.9 343.80 397.40 7.38 48.6 50.76 195.5 49.68 49.68130.6 48.6 54.00 143.80 17.32 23 23.46 80.04 22.54 22.54 66.6 23.4626.22 107.45 33.13 13.95 13.95 28.62 13.71 13.71 62.56 14.19 16.60 98.1258.21 9.99 9.72 17.52 10.13 9.45 62.72 10.68 12.32 91.23 85.00 8.63 8.1613.31 8.81 8.25 61.56 9.66 10.50 84.25

Table 1 shows the viscosification behavior of the ZGS with varying TEOSconcentrations as a function of shear rate and temperature. It can beobserved that the shutoff composition exhibits a shear thinning behaviorand thus making the shutoff composition easier to pump and place in thedownhole water (or gas) producing zone. Furthermore, the shutoffcomposition exhibits gelation as the temperature increases.

A number of implementations have been described. Nevertheless, it willbe understood that various modifications may be made without departingfrom the spirit and scope of the disclosure.

What is claimed is:
 1. A pill comprising a pill as applied to a wellboreformed through Earth surface in a subterranean formation, the pillcomprising: a zwitterionic gemini surfactant (ZGS); a salt; anorthosilicate; an acid; and water.
 2. The pill of claim 1, wherein theZGS comprises:

wherein n₁=8 to 18, n₂=3 to 6, and n₃=3 or 4, and wherein the functionalgroup R is a sulfonate group, a carboxylate group, an aldehyde group, ora hydroxyl group.
 3. The pill of claim 1, wherein the acid compriseshydrochloric acid.
 4. The pill of claim 1, wherein the orthosilicatecomprises tetraethyl orthosilicate (TEOS) or tetramethyl orthosilicate(TMOS), or a combination thereof, wherein the salt comprises calciumchloride, sodium chloride, potassium chloride, sodium bromide, sodiumcitrate, or sodium salicylate, or any combinations thereof, and whereinas applied to the wellbore comprises as formulated at the Earth surfaceand as injected into the wellbore.
 5. The pill of claim 4, whereinconcentration of the ZGS in the pill is in a range of 2.5 wt % to 10 wt%, wherein concentration of the salt in the pill is in a range of 5 wt %to 30 wt %, wherein concentration of the orthosilicate in the pill is ina range of 1 wt % to 10 wt %, wherein concentration of the acid in thepill is at least one molar equivalent to the orthosilicate, and whereinas injected into the wellbore comprises as pumped into the wellbore. 6.A method of treating a region of a subterranean formation adjacent awellbore zone of a wellbore, the method comprising: injecting a gellabletreatment composition through the wellbore zone into the region of thesubterranean formation adjacent the wellbore zone; allowing the gellabletreatment composition to gel in the region via heat provided by theregion to prevent or reduce flow of an unwanted fluid from the regioninto the wellbore zone, wherein allowing the gellable treatmentcomposition to gel comprises forming nanoparticles in-situ in the regionvia the gellable treatment composition; and producing desiredhydrocarbon from the subterranean formation through the wellbore toEarth surface, wherein a gel formed from the gellable treatmentcomposition in the region prevents or reduces production of the unwantedfluid from the region into the wellbore, wherein the gel comprises thenanoparticles, wherein the gellable treatment composition as injectedcomprises ZGS, salt, orthosilicate, acid, and water.
 7. A method oftreating a region of a subterranean formation adjacent a wellbore zoneof a wellbore, the method comprising: injecting a gellable treatmentcomposition through the wellbore zone into the region of thesubterranean formation adjacent the wellbore zone, wherein the gellabletreatment composition comprises an activator and zwitterionic geminisurfactant (ZGS) that is a viscoelastic surfactant (VES), and whereinthe gellable treatment composition comprises orthosilicate or anothersource of silica that is catalyzed in situ via an acid in the gellabletreatment composition into nanoparticles; allowing the gellabletreatment composition to gel in the region via heat provided by theregion to prevent or reduce flow of an unwanted fluid from the regioninto the wellbore zone, wherein allowing the gellable treatmentcomposition to gel comprises forming nanoparticles in-situ in the regionvia the gellable treatment composition; and producing desiredhydrocarbon from the subterranean formation through the wellbore toEarth surface, wherein a gel formed from the gellable treatmentcomposition in the region prevents or reduces production of the unwantedfluid from the region into the wellbore, and wherein the gel comprisesthe nanoparticles.
 8. The method of claim 7, wherein the gellabletreatment composition is a shutoff composition to shutoff the flow ofthe unwanted fluid into the wellbore zone, and wherein the unwantedfluid comprises water or natural gas, or both.
 9. The method of claim 7,wherein the nanoparticles comprise silica nanoparticles.
 10. The methodof claim 9, wherein the orthosilicate comprises tetramethylorthosilicate (TMOS) or tetraethyl orthosilicate (TEOS), or acombination thereof.
 11. The method of claim 9, wherein the acidcomprises hydrochloric acid.
 12. The method of claim 7, wherein allowingthe gellable treatment composition to gel comprises gelling of the ZGSin the region via the activator, and wherein heat from the regionincreasing temperature of the gellable treatment composition promotesgelling of the ZGS.
 13. The method of claim 12, wherein the activatorcomprises salt, wherein the nanoparticles comprise silica nanoparticles,and wherein the ZGS comprises:

wherein n₁=8 to 18, n₂=3 to 6, and n₃=3 or 4, and wherein R is asulfonate, a carboxylate, an aldehyde, or a hydroxyl group.
 14. Themethod of claim 7, wherein the gellable treatment composition comprisesthe activator to promote gelling of the gellable treatment compositionin the region along with the heat provided by the region, and whereinthe heat provided by the region increases temperature of the gellabletreatment composition in the region.
 15. The method of claim 14, whereinthe activator comprises salt, and wherein allowing the gellabletreatment composition to gel comprises gelling of the ZGS in the regionvia the salt.
 16. The method of claim 15, wherein the salt comprisescalcium chloride, sodium chloride, potassium chloride, sodium bromide,sodium citrate, or sodium salicylate, or any combinations thereof.